Process and apparatus for alkylating and hydrogenating a light cycle oil

ABSTRACT

One exemplary embodiment can be a process for alkylating and hydrogenating a light cycle oil. The process can include passing the light cycle oil, one or more C2-C6 alkenes, and hydrogen through a reaction vessel containing an alkylation zone and a hydrogenation zone. Generally, the hydrogen is at least partially comprised from a hydrocarbon product stream from a fluid catalytic cracking zone.

FIELD OF THE INVENTION

This invention generally relates to a process and apparatus foralkylating and hydrogenating a light cycle oil.

DESCRIPTION OF THE RELATED ART

Generally, some of the demand for transportation fuel has been shiftingtoward a middle distillate, such as diesel fuel. A light cycle oil(hereinafter may be abbreviated “LCO”) can have a boiling point rangethat may fall within the diesel range. The LCO is typically blended intothe diesel pool. However, the quantity of blended LCO may be limitedbecause the typical level of contaminates in the LCO can be high and thecetane number may be low, making LCO undesirable as a diesel fuel. Oneapproach to upgrading LCO may include hydrotreating. Unfortunately,although this approach can reduce sulfur amounts to meet specifications,a significant amount of hydrogen may be required. In many refineries,hydrogen may be in a limited supply and can be a relatively valuablecommodity.

Another approach may be subjecting the LCO to hydrotreating followed byselective ring opening. The hydrogen consumption may be even higher thanfor deep hydrotreating, and significant amounts of gasoline may beproduced along with the desired diesel fraction. Gasoline may beco-produced because the activation energy for the ring opening may begreater than for the dealkylation or side chain cracking. Therefore, itis difficult to open the aromatic rings without dealkylating the sidechains. However, refineries may have significant amounts of lightalkenes, e.g., C2-C6 alkenes, generated by units such as fluid catalyticcracking. Generally, it would be beneficial to convert C2-C6 olefins toa middle distillate fuel product, such as diesel, instead of gasoline insome instances. At a minimum, it would be advantageous to provide therefinery the flexibility to manufacture a desired fuel to meet thecurrent demand.

SUMMARY OF THE INVENTION

One exemplary embodiment can be a process for alkylating andhydrogenating a light cycle oil. The process can include passing thelight cycle oil, one or more C2-C6 alkenes, and hydrogen through areaction vessel containing an alkylation zone and a hydrogenation zone.Generally, the hydrogen is at least partially comprised from ahydrocarbon product stream from a fluid catalytic cracking zone.

Another exemplary embodiment may be a process for alkylating andhydrogenating a light cycle oil. The process can include passing thelight cycle oil, one or more C2-C6 alkenes, and hydrogen upwards througha reaction vessel containing a reaction zone for alkylating andhydrogenating the light cycle oil, and sending a catalyst from thereaction zone to a regeneration zone in a catalytic cracking zone.

Yet another exemplary embodiment can be an apparatus that may include acatalytic cracking zone, a fractionation zone, a separation zone, atreatment zone, and a reaction vessel. The catalytic cracking zone mayproduce a hydrocarbon product stream. Typically, the fractionation zonereceives the hydrocarbon product stream and provides a light naphthastream and a light cycle oil stream. The separation zone may separate astream including hydrogen and ethene from the light naphtha stream.Generally, the treatment zone is adapted to receive the stream includinghydrogen and ethene, and may include a first removal zone for removinghydrogen sulfide, and a washing zone for removing ammonia. Usually, thereaction vessel is provided for alkylating and hydrogenating the lightcycle oil stream. The reaction vessel may receive a feed includinghydrogen and one or more C2-C6 alkenes, and the light cycle oil stream.The light cycle oil and hydrogen may be obtained from the hydrocarbonproduct stream.

The embodiments disclosed herein can provide a process and an apparatusfor upgrading an LCO for utilization as a middle distillate fuelproduct, such as diesel fuel. Particularly, the embodiments hereinprovide a process for increasing the cetane number of an LCO. As such,the embodiments provided herein can allow utilization of light alkenesranging from C2-C6 to alkylate aromatics. As a result, the 2-ring and3-ring aromatics that may be present in the LCO can be upgraded to allowblending of the treated LCO in various diesel tankage in the refinery.Thus, the embodiments disclosed herein can provide flexibility inshifting fuel production from gasoline to diesel fuel or vice-versa.Furthermore, components in a fluid catalytic cracking off-gas may alsobe utilized in the process and be upgraded from typical use, such asfuel gas. The hydrogen containing stream, often referred to as an FCCdry-gas that may contain up to about 15%, typically about 10-about 15%,by volume, hydrogen, can be used for saturating aromatics as well asremoving other impurities by processes such as hydrodesulfurizing andhydrodenitrogenating. In addition, any ethene in the FCC dry-gas mayalso be used for alkylating one or more aromatics in the LCO. As aconsequence, the quality of the product, such as diesel fuel, can befurther improved. By coupling aromatic alkylation with hydrotreating,the refinery can potentially produce middle distillate fuels, such asdiesel fuels, by meeting sulfur and cetane number specifications andutilizing light alkenes.

DEFINITIONS

As used herein, the term “stream” can include various hydrocarbonmolecules, such as straight-chain, branched, or cyclic alkanes, alkenes,alkadienes, and alkynes, and optionally other substances, such as gases,e.g., hydrogen, or impurities, such as heavy metals, and sulfur andnitrogen compounds. The stream can also include aromatic andnon-aromatic hydrocarbons. Moreover, the hydrocarbon molecules may beabbreviated C1, C2, C3 . . . Cn where “n” represents the number ofcarbon atoms in the one or more hydrocarbon molecules. Furthermore, asuperscript “+” or “−” may be used with an abbreviated one or morehydrocarbons notation, e.g., C3⁺ or C3⁻, which is inclusive of theabbreviated one or more hydrocarbons. As an example, the abbreviation“C3⁺” means one or more hydrocarbon molecules of three carbon atomsand/or more. Typically, a stream can include at least one of hydrogen,one or more alkenes, a light naphtha, a heavy naphtha, a light cycleoil, a heavy cycle oil, and a heavy slurry oil.

As used herein, the term “zone” can refer to an area including one ormore equipment items and/or one or more sub-zones. Equipment items caninclude one or more reactors or reactor vessels, heaters, exchangers,pipes, pumps, compressors, and controllers. Additionally, an equipmentitem, such as a reactor, dryer, or vessel, can further include one ormore zones or sub-zones.

As used herein, the term “rich” can mean a stream exiting a vessel thatmay have a concentration of one or more compounds exceeding a streamentering the vessel.

As used herein, the term “lean” can mean a stream exiting a vessel thatmay have a concentration of one or more compounds less than a streamentering the vessel.

As used herein, the term “dilute” can mean no more than about 50%, byvolume, of an individual compound, such as hydrogen, in a stream.

As used herein, the term “substantially” can mean an amount of at leastgenerally about 80%, preferably about 90%, and optimally about 99%, bymole, of a compound or class of compounds in a stream.

As used herein, the term “cetane number” can mean a diesel fuel ratingcomparable to the octane-number rating for gasoline. Typically, it isthe percentage of cetane (C₁₆H₃₄) that is mixed with heptamethylnonaneto give the same ignition performance under standard conditions as thefuel in question. The derived cetane number for a diesel fuel can bedetermined by ASTM D6890-09.

As used herein, the term “gasoline” may be a mixture of volatilehydrocarbons suitable for use in a spark-ignited internal combustionengine and having an octane number of at least 60. The major componentscan include branch and straight chain paraffins, cyclic paraffins, andaromatics. The standard specifications for gasoline can be determined byASTM D4814-09b.

As used herein, the term “light naphtha” can be a fraction boiling up toabout 90° C. and can include up to 6 carbon atom molecules and othergases. As an example, a light naphtha can include one or more ofmethane, ethane, ethene, propane, propene, butane, butene, pentane,pentene, hexane, hexene, hydrogen, hydrogen sulfide, carbon monoxide,and nitrogen. Typically, a light naphtha can include gasoline, one ormore C1-C5 hydrocarbons, and hydrogen.

As used herein, the term “heavy naphtha” can be a fraction boiling fromabout 90-about 200° C. and include one or more molecules of 6-12 carbonatoms.

As used herein, the term “light cycle oil” may be a cycle oil fromcatalytic cracking that can be used as a feed in hydrocracking andtypically has a boiling point in the range of about 205-about 400° C.Typically, the light cycle oil can contain about 8-about 20 carbon atomsper molecule.

As used herein, “heavy cycle oil” can include compounds having about20-about 70 carbon atoms per molecule. A heavy cycle oil maysubstantially include components boiling in the range of about 340-about570° C.

As used herein, the terms “alkene” and “olefin” may be usedinterchangeably.

As used herein, the term “communication” can mean that material flow isoperatively permitted, directly or indirectly, between enumeratedcomponents.

As used herein, the term “overhead stream” can mean a stream, typicallyincluding one or more gases, which may be removed at or proximate to atop of a vessel.

As used herein, the term “bottom stream” can mean a stream, typicallyincluding one or more liquids, which may be removed at or proximate to abottom of a vessel.

As used herein, the terms “absorption” and “adsorption” may includeprocesses such as, respectively, adsorption and absorption.

As used herein, the term “zeolite” can refer to a topological structureof a molecular sieve as described by Atlas of Zeolite-Framework Typesmaintained by the International Zeolite Association StructureCommission.

As used herein, the term “FAU zeolite” can include any zeolite of theFAU structure such as zeolite X or zeolite Y.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic depiction of an exemplary apparatus for alkylatingand hydrogenating an LCO.

FIG. 2 is a schematic depiction of another version of an exemplaryapparatus for alkylating and hydrogenating an LCO.

DETAILED DESCRIPTION

Referring to FIG. 1, an apparatus 90 for alkylating and hydrogenating anLCO can include a catalytic cracking zone 100, a fractionation zone 200,a separation zone 300, a treatment zone 400, and a reaction vessel 500.It should be noted that process flow lines in the figures can bereferred to as, e.g., lines, portions, gases, feeds, products, orstreams. Particularly, a line can contain one or more portions, gases,feeds, products, or streams, and one or more portions, gases, feeds,products, or streams can be contained by a line.

The catalytic cracking zone 100 can include a riser 120 or riser reactor120, a reactor 140, and a regeneration zone 180. The riser 120 canreceive a fluidizing gas 50 and a catalytic cracking feed 70. Generally,the catalytic cracking zone 100 is preferably a fluid catalytic cracking(may be abbreviated herein as “FCC”) zone 100. Although the reactor 140can include a fixed bed, a moving bed, or a fluidized bed, preferablythe reactor 140 is a fluidized bed.

Generally, the reactor 140 can communicate with the riser 120. The riser120 can receive a feed 70 that can have a boiling point of about180-about 800° C. Typically, the feed 70 can be at least one of a gasoil, a vacuum gas oil, an atmospheric gas oil, and an atmosphericresidue. Alternatively, the feed 70 can be at least one of a heavy cycleoil and a slurry oil. Generally, the feed 70 can be provided at anysuitable height on the riser 120, such as above the fluidizing gas 50including steam and/or a light hydrocarbon. The feed 70 can be providedat a distance sufficient to provide a good dispersion of the up-flowstream containing the feed and/or catalyst, if desired.

The catalyst can be a single catalyst or a mixture of differentcatalysts. In one exemplary embodiment, the catalyst may include twocomponents or catalysts, namely a first component or catalyst, andoptionally a second component or catalyst. Such a catalyst mixture isdisclosed in, e.g., U.S. Pat. No. 7,312,370 B2.

Generally, the first component may include any of the well-knowncatalysts that are used in the art of FCC, such as an active amorphousclay-type catalyst and/or a high activity, crystalline molecular sieve.Zeolites may be used as molecular sieves in FCC processes. Preferably,the first component includes a large pore zeolite, such as a Y-typezeolite, an active alumina material, a binder material, including eithersilica or alumina, and an inert filler such as kaolin.

Typically, the zeolitic molecular sieves appropriate for the firstcomponent have a large average pore size. Usually, molecular sieves witha large pore size have pores with openings of greater than about 0.7 nmin effective diameter defined by greater than about 10, and typicallyabout 12, member rings. Suitable large pore zeolite components mayinclude synthetic and natural zeolites of the FAU and MOR structuretypes. A portion of the first component, such as the zeolite, can haveany suitable amount of a rare-earth metal or rare-earth metal oxide.

The second component if, e.g., a light alkene product is desired, mayinclude a medium or smaller pore zeolite catalyst, such as an MFI, MEL,and/or FER structure types.

Preferably, the second component has the medium or smaller pore zeolitedispersed on a matrix including a binder material such as silica oralumina and an inert filler material such as kaolin. The secondcomponent may also include some other active material such as a betazeolite. These compositions may have a crystalline zeolite content ofabout 10-about 50%, by weight or more, and a matrix material content ofabout 50-about 90%, by weight. Components containing about 40%, byweight, crystalline zeolite material are preferred, and those withgreater crystalline zeolite content may be used. Generally, medium andsmaller pore zeolites are characterized by having an effective poreopening diameter of less than or equal to about 0.6 nm, and rings ofabout 10 or fewer members.

The total catalyst mixture in the reactor 140 may contain about 1-about25%, by weight, of the second component, namely a medium to small porecrystalline zeolite with greater than or equal to about 1.75%, byweight, of the second component being preferred. When the secondcomponent contains about 40%, by weight, crystalline zeolite with thebalance being a binder material, an inert filler, such as kaolin, andoptionally an active alumina component, the mixture may contain about4-about 40%, by weight, of the second catalyst with a preferred contentof at least about 7%, by weight. The first component may comprise thebalance of the catalyst composition.

Generally, the feed 70 in the catalyst mixture can be providedapproximate to the bottom of a riser 120. Typically, the riser 120operates with dilute phase conditions above the point of feed injectionwith a density that is less than about 320 kg/m³. Generally, the feed 70may be introduced into the riser 120 by a nozzle. Usually, the feed 70can have a temperature of about 140-about 300° C. Moreover, additionalamounts of feed may be introduced downstream of the initial feed point.

In one exemplary embodiment, heat from the regenerated catalyst gasifiesthe hydrocarbon feed or oil, and the hydrocarbon feed is thereaftercracked to lighter molecular weight hydrocarbon products in the presenceof the catalyst as both are transferred up the riser 120 into thereactor 140. Usually the feed 70 reacts within the riser 120 to form oneor more products. The riser 120 can operate at any suitable temperature,and typically operates at a temperature of about 400-about 600° C. at apressure of no more than about 510 kPa. Typically, side reactions occurin the riser 120 leaving coke deposits on the catalyst that lowercatalyst activity. The cracked light hydrocarbon products can thereafterbe separated from the coked cracking catalyst using one or more stagesof product disengagers and/or cyclones in the reactor 140. Gaseous,cracked products can exit the reactor 140 as a hydrocarbon productstream to a downstream fractionation zone 200, as hereinafter described.The spent or coked catalyst may require regeneration for further use.Coked cracking catalyst, after separation from the gaseous hydrocarbonproducts and steam stripping to purge any residual hydrocarbon gases,may be carried to the regeneration zone 180 through a spent catalystline 164.

The regeneration zone 180 can include a regenerator 182, also known as acombustor 182. However, other types of regenerators are suitable. Astream of oxygen-containing gas 184, such as air, may be introduced intothe regenerator 182 to contact the coked catalyst. Generally, coke iscombusted from the coked catalyst to provide a regenerated catalyst anda flue gas stream 188. However, metals present in the catalytic crackingfeed 70 typically are not removed through this combustion regeneration.The catalyst regeneration process can add a substantial amount of heatto the catalyst, providing energy to offset the endothermic crackingreactions occurring in the riser 120. Catalyst and air flow upwardlytogether within the regenerator 182 and, after regeneration, can beseparated by one or more stages of catalyst disengagers and/or cyclones.Regenerated metal-containing catalyst may be carried back to the riser120 through the regenerated catalyst line 168. Hot flue gas exits thetop of the catalyst regenerator 182 as the flue gas stream 188 forfurther processing. The catalyst regeneration temperature can be about500-about 900° C., and a pressure of no more than about 510 kPa. As aresult of the coke burning, the flue gas stream 188 can contain carbonmonoxide, carbon dioxide, nitrogen, and water, along with smalleramounts of other compounds. Exemplary reaction zones and regenerationzones are disclosed in, e.g., U.S. Pat. No. 4,090,948; U.S. Pat. No.5,154,818; and U.S. Pat. No. 7,312,370 B2.

The one or more products leaving the reactor 140 can exit as thehydrocarbon product stream 160 optionally in a gas phase to thefractionation zone 200. The fractionation zone 200 can include anysuitable number of distillation columns, such as one or moredistillation columns, and produce a variety of streams or products 210,220, 230, 240, and 250. Typically, a main column can provide a lightnaphtha stream 210, a heavy naphtha stream 220, a light cycle oil stream230, a heavy cycle oil stream 240, and a heavy slurry oil stream 250.Any or all of these may be optionally cooled and pumped back to the maincolumn, typically at a higher location. The light naphtha streamincluding gasoline and gaseous light hydrocarbons can be cooled tocondense heavier components before entering a first receiver 310 of theseparation zone 300. Such fractionation zones are disclosed in, e.g.,U.S. Pat. No. 3,470,084.

The separation zone 300 can include the first receiver 310, a secondreceiver 320, a compressor 330, a first absorber 340, a second absorber350, and another fractionation zone 360. The receiver 310 can provide anoverhead stream 314 including one or more gaseous light hydrocarbons andhydrogen, and the hydrogen can be relatively diluted. A bottom stream318 can include a condensed unstabilized gasoline and at least a portionprovided to the first absorber 340, as hereinafter described, andtypically another portion refluxed to a column in the fractionation zone200. Optionally, a boot can be provided to remove any water from thereceiver 310.

The separation zone 300 can include a gas recovery section based on anabsorption system, but any suitable gas recovery system may be used,including a cold box system. To obtain sufficient separation of lightgas components, the overhead stream 314 may be compressed in acompressor 330, which can use one or more compressor stages, such as adual stage compression. Generally, the compressor 330 controls thepressure in downstream zones and equipment, such as the reaction vessel500. A compressed stream 334 may be joined by streams 344 and 362, ashereinafter described, cooled, and provided to a second receiver 320. Abottom stream 328 can be sent to another separation zone 360, ashereinafter described. An overhead stream 324 including one or moregases, including dilute hydrogen and ethene, may be routed to a firstabsorber 340. In the first absorber 340, the gases in the overheadstream 324 may be contacted with the bottom stream 318 from the firstreceiver 310 including an unstabilized gasoline. This contacting mayeffect at least a partial separation between C3⁺ and C2⁻ hydrocarbons. Abottom stream 344 including one or more liquid C3⁺ hydrocarbons can becombined with streams 334 and 362 before cooling and transferring to thesecond receiver 320. An overhead stream 342, including a primaryoff-gas, may include dilute hydrogen and ethene optionally with varyingimpurities such as hydrogen sulfide and ammonia. Thus, at least aportion of the light naphtha stream 210 may be processed by separatingand compressing to obtain the overhead stream 342. In one preferredembodiment, this dilute hydrogen stream 342 can directed to a secondaryabsorber 350. A first portion 232 of the LCO stream 230 may be divertedand used to contact counter-currently the gases in the dilute hydrogenstream 342. The light cycle oil may absorb at least some or asubstantial part of any remaining one or more C3⁺ hydrocarbons. A bottomstream 354 including a light cycle oil that can be rich in one or moreC3⁺ hydrocarbons may be returned to the fractionation zone 200. Anoverhead stream 352 of the secondary adsorber 350, including a dilutedhydrogen, can include an FCC dry gas of predominantly one or more C2⁻hydrocarbons, including ethene.

Typically, the dilute hydrogen stream 352 can include about 1-about 25%,by weight, hydrogen, about 1-about 25%, by weight, nitrogen, about25-about 55%, by weight, methane, about 5-about 45%, by weight, ethane,about 5-about 50%, by weight, ethene, and no more than about 5%, byweight, of one or more C3⁺ hydrocarbons including no more than about0.5%, by weight, propene, based on the weight of the dilute hydrogenstream 352. Impurities in the dilute hydrogen stream 352 can includehydrogen sulfide, ammonia, one or more carbon oxides, such as carbonmonoxide, and saturation levels of water.

The dilute hydrocarbon stream 352 can be sent to a treatment zone 400 toremove hydrogen sulfide, ammonia, and carbon monoxide and can include,optionally and independently, a first removal zone 420, a washing zone430, and a second removal zone 440. Many impurities in a dry gas streamcan poison an alkylation and a hydrogenation catalyst. Carbon monoxidecan adsorb on metal sites, reducing activity. Ammonia can attack acidsites on the catalyst. Hydrogen sulfide may adversely impact metalfunctions on a catalyst. Acetylene can polymerize and gum the catalystor equipment.

The first removal zone 420 can receive the dilute hydrogen stream 352and may have an optional amine absorber unit to remove hydrogen sulfideto a lower concentration. Such a vessel may include trays and othercontacting devices to enhance the interaction of the amine solvent andgases. Typically, the dilute hydrogen stream 352 has a hydrogen sulfideconcentration of no more than about 1,000 ppm, by weight, based on theweight of the dilute hydrogen stream 352 that can be reduced, afterabsorption, to a hydrogen sulfide concentration of no more than about 50ppm, by weight, based on the weight of the outlet stream 422. A leanaqueous amine solution, including, e.g., monoethanol amine or diethanolamine, may be introduced and contacted with the gases to adsorb hydrogensulfide. Subsequently, a rich aqueous amine absorption solutioncontaining hydrogen sulfide may be removed from the first removal zone420.

Optionally, the outlet stream 422 can be provided to the washing zone430 to remove residual amine carried over from the first removal zone420 and reduce the concentration of ammonia and carbon dioxide of thedilute hydrogen stream 422. Water, optionally slightly acidified, may beintroduced into a water wash vessel to enhance capture of basicmolecules, such as the amine. Such a vessel may include trays and othercontacting devices to enhance the interaction of the water and gases. Anaqueous stream containing one or more amines, and potentially ammoniaand carbon dioxide can leave the washing zone 430. Typically, the outletstream 422 has an ammonia concentration of about 1,000 ppm, by weight,based on the weight of the stream 422 entering the washing zone 430 andcan exit as an outlet stream 432 having an ammonia concentration ofabout 50 ppm, by weight, based on the weight of the outlet stream 432.

In one preferred embodiment, the outlet stream 432 can be provided tothe second removal zone 440. The second removal zone 440 can include aguard bed to remove one or more of the impurities such as carbonmonoxide, hydrogen sulfide and ammonia down to lower concentrations, butprimarily reduce carbon monoxide. The guard bed may contain an adsorbentto adsorb impurities such as hydrogen sulfide that may poison acatalyst, or multiple adsorbents for adsorbing more than one type ofimpurity. Such adsorbents are commercially available from, e.g. UOP LLCof Des Plaines, Ill. The adsorbents may be mixed in a single bed or canbe arranged in successive beds. In one exemplary embodiment, the stream432 prior to entering the guard bed 440 can include no more than about2%, by weight, or about 1%, by weight, carbon monoxide, based on theweight of the stream 432. After exiting the second removal zone 440, anoutlet stream 442 or hydrogen stream 442 can have no more than about 100ppm, by weight, carbon monoxide based on the weight of the stream 442.This hydrogen stream 442, typically having a dilute concentration ofhydrogen, can be provided to the reaction vessel 500 after combinationwith other streams, as hereinafter described. Thus, the hydrogen stream442 after passing through the treatment zone 400 can include no morethan about 50 ppm, by weight, hydrogen sulfide, no more than about 50ppm, by weight, ammonia, and optionally no more than about 100 ppm, byweight, carbon monoxide, based on the weight of the hydrogen stream 442.Although these impurities have been discussed, it should be understoodthat other impurities, such as water and/or acetylene, can also beremoved.

Another fractionation zone 360 can receive the bottom stream 328 fromthe second receiver 320. The another fractionation zone 360 can includeone or more columns. In one exemplary zone these one or more columns caninclude a stripper, a debutanizer column, and/or a naphtha splitter. Theanother fractionation zone 360 can provide a stream 362 including one ormore C2⁻ hydrocarbons and other gases typically from a stripper that canbe combined with the streams 334 and 344 prior to cooling and passing tothe receiver 320. Moreover, the fractionation zone 360 can provide astream 364 including one or more C3-C4 alkenes, typically from anoverhead stream of a debutanizer column. Additionally, the fractionationzone 360 can provide a stream 366 including one or more C5-C6 alkenes,typically from an overhead stream of a naphtha splitter. The streams 364and 366 can, optionally and independently, be combined with the dilutestream 442. Furthermore, the naphtha splitter may provide a bottomstream 368 including a stabilized gasoline that may be further treatedand sent to gasoline storage and blending.

The reaction vessel 500 can include an alkylation zone 520 and ahydrogenation zone 540 and receive a feed 490. The feed 490 can includeone or more of the streams 442, 364, 366, and 394. The stream 394 can bea make-up hydrogen stream to supplement any missing hydrogen to increasethe partial pressure of hydrogen. Thus, the streams 442 and 394 cancomprise a combined hydrogen stream 396. The feeding of the stream 442,which can contain hydrogen and one or more alkenes, to the reactionvessel 500 can result in formation of single ring aromatics withadditional alkyl functional groups and saturation of aromatic rings whencombined with a second portion 234 of the LCO stream 230. Moreover, ifthe stream 442 has sufficient quantities of ethene, the addition of thestreams 364 and 366 can be omitted. The reaction vessel 500 may be afluidized bed reactor, moving bed reactor, fixed bed reactor or otherknown reactor type. In this exemplary embodiment, as depicted, it can bea fixed bed reactor.

In yet a further embodiment, at least one of the streams 364 and 366 canbe introduced at the inlet of the reaction vessel 500 with the LCO tocontact the catalyst with acid function, while at least a portion of thestreams 442, 394, 364, and 366 can be introduced to the hydrogenationzone 540.

The alkylation zone 520 can include any suitable catalyst, such as atleast one of zeolite from the FAU, MFI or ZSM-5, *BEA or beta zeolite,and MWW structure types, or an UZM-8 zeolite. Desirably, the catalysthas acidic components to facilitate alkylation. The LCO can contain asignificant quantity of 2-ring aromatic and appreciable amounts of3-ring aromatic and 1-ring aromatic compounds. Generally, the acidic andhydrogenation components of the catalyst can reside in separateparticles.

The hydrogenation zone 540 can include any suitable catalyst, such as acatalyst containing a metal from groups 5-6, and 8-10 of the periodictable, such as a metal of vanadium, chromium, molybdenum, tungsten,nickel, palladium, and platinum. The metal can be deposited on anysuitable support, such as a zeolite or an alumina. Although thesecatalysts have been disclosed for the zones 520 and 540, any suitablecatalyst for the alkylation and hydrogenation of the aromatic andnaphthenoaromatic molecules present in the LCO may be used.

Although not wanting to be bound by theory, the acidic particle cancontact the feed 490 first to alkylate the aromatic ring, and thealkylation product can contact a second catalyst carrying thehydrogenation components to saturate one or more of the multi-aromaticrings. The overall effect is to produce a product stream with increasednumbers of alkyl functional groups, and higher cetane number incomparison with LCO feed entering the reaction vessel 500.

One advantage of catalyst particles having separate acidic andhydrogenation functions can be allowing the alkylation and saturationreactions to take place under more optimal process conditions for therespective reactions. In addition, the saturation of the aromatic ringcan take place afterwards to avoid saturating the olefin feed componentsdesigned to alkylate the aromatic ring. The alkylation zone 520 and thehydrogenation zone 540 can operate, independently, at a temperature ofabout 100-about 400° C., a pressure of about 790 kPa-about 7,000 kPa,preferably 1,500-about 7,000 kPa, and a space velocity of about0.1-about 10 hr⁻¹. In addition, the alkylation zone 520 and thehydrogenation zone 540 can operate in a trickle bed or a gas phaseoperation.

In another exemplary embodiment, the zones 520 and 540 can contain thesame catalyst possessing both alkylation and hydrogenation functions. Insuch an instance, conditions can be tailored, such as low hydrogenpartial pressure, so the rate of alkylation exceeds the rate ofhydrogenation so mostly alkylation occurs in the zone 520. Raising thehydrogen partial pressure can ensure that mostly hydrogenation, oralkylation and hydrogenation, occurs in the zone 540. In a still furtherexemplary embodiment, the zones 520 and 540 can be combined into asingle zone with mostly alkylation occurring in the first part of thezone and mostly hydrogenation, or alkylation and hydrogenation,occurring in the second part of the zone.

The reaction vessel 500 can produce an alkylated and hydrogenatedproduct stream 550. In one exemplary embodiment, the product steam 550may be sent to a stripper for removing most of the light gases such asunreacted hydrogen, methane, ethane, unreacted olefins and lightimpurities. These light gases can be utilized as a typical fuel gas togenerate steam or power. A liquid bottoms stream from the stripper canbe sent to a diesel fuel pool for use as an improved diesel fuel or LCOblending stock. Alternatively, a portion of the liquid bottoms streamcan be recycled back to the reaction vessel 500 for further upgrading.

Referring to FIG. 2, another version of the apparatus 90 is disclosed.In this version, the reaction vessel 500 can be replaced with a reactionvessel 600, which may be a fluidized bed reactor operating in an upflowoperation, and can contain at least one reaction zone 610. Generally,the utilized catalyst can be the same as the catalytic cracking zone100, as described above. Particularly, the feed 490 can include streams442, 364, 366, and 394. However, a fresh catalyst can be provided by aline 602 and combined with the feed 490. The hydrogen and alkene feed490 can enter an inlet 604 to alkylate and hydrogenate the LCO 234,which can be provided proximate to the inlet 604, as well. The LCO maybe alkylated and hydrogenated in contact with the feed 490 and thecatalyst from a line 630 rising in the reaction vessel 600. Thealkylated and hydrogenated product stream 550 can exit, and be sent to astripper, as described above.

Spent or partially spent catalyst can be withdrawn from the reactionvessel 600 proximate to the outlet 608 and routed via a line 620 to theline 164, where the catalyst can be sent to the regeneration zone 180.Afterwards, the catalyst can be regenerated, and a portion removed fromthe line 168 and provided to the reaction vessel 600 via the line 630.

Generally, the embodiments disclosed herein can provide an improved fuelquality such as increased cetane numbers, lowered sulfur contents, andreduced end points for the LCO. Moreover, the LCO may have an increasedalkyl functional group and 1-ring aromatic compounds in comparison withLCO feed entering the reaction vessel. Consequently, an increasedproportion of the LCO can be blended in the diesel pool.

Without further elaboration, it is believed that one skilled in the artcan, using the preceding description, utilize the present invention toits fullest extent. The preceding preferred specific embodiments are,therefore, to be construed as merely illustrative, and not limitative ofthe remainder of the disclosure in any way whatsoever.

In the foregoing, all temperatures are set forth in degrees Celsius and,all parts and percentages are by weight, unless otherwise indicated.

From the foregoing description, one skilled in the art can easilyascertain the essential characteristics of this invention and, withoutdeparting from the spirit and scope thereof, can make various changesand modifications of the invention to adapt it to various usages andconditions.

1. A process for alkylating and hydrogenating a light cycle oil,comprising: A) passing the light cycle oil, one or more C2-C6 alkenes,and hydrogen through a reaction vessel containing an alkylation zone anda hydrogenation zone wherein the hydrogen is at least partiallycomprised from a hydrocarbon product stream from a fluid catalyticcracking zone.
 2. The process according to claim 1, wherein the lightcycle oil passes through the alkylation zone and then the hydrogenationzone.
 3. The process according to claim 1, further comprising passingthe hydrocarbon product stream from the fluid catalytic cracking zone toa fractionation zone providing a light naphtha stream and the lightcycle oil.
 4. The process according to claim 3, further comprisingseparating and compressing at least a portion of the light naphthastream to provide the hydrogen to the reaction vessel.
 5. The processaccording to claim 1, wherein the alkylation zone contains a catalystcomprising a zeolite comprising at least one of a FAU zeolite, a betazeolite, a ZSM-5 zeolite, an MWW zeolite, and an UZM-8 zeolite, and thehydrogenation zone contains a catalyst comprising a support and at leastone element of group 5, group 6, or groups 8-10 of the periodic table.6. The process according to claim 5, wherein the at least one element ofgroup 5 comprises vanadium, the at least one element of group 6comprises at least one chromium, molybdenum, and tungsten; and the atleast one element of groups 8-10 comprises at least one of nickel,palladium, and platinum.
 7. The process according to claim 3, furthercomprising separating a stream comprising hydrogen from the lightnaphtha stream provided to the reaction vessel.
 8. The process accordingto claim 7, wherein the hydrogen stream comprises ethene.
 9. The processaccording to claim 1, wherein the alkylation zone and the hydrogenationzone are, independently, at a temperature of about 100-about 400° C. anda pressure of about 700-about 2,900 kPa.
 10. The process according toclaim 7, further comprising treating the hydrogen stream where thehydrogen stream comprises no more than about 50 ppm, by weight, hydrogensulfide, no more than about 50 ppm, by weight, ammonia, and optionallyno more than about 100 ppm, by weight, carbon monoxide, based on theweight of the hydrogen stream prior to being combined with the lightcycle oil and one or more C2-C6 alkenes.
 11. A process for alkylatingand hydrogenating a light cycle oil, comprising: A) passing one or moreC2-C6 alkenes, hydrogen, and the light cycle oil upwards through areaction vessel containing a reaction zone for alkylating andhydrogenating the light cycle oil; and B) sending a catalyst from thereaction zone to a regeneration zone in a catalytic cracking zone. 12.The process according to claim 11, wherein the catalyst comprises afirst component comprising a FAU zeolite and a second componentcomprising an MFI zeolite.
 13. The process according to claim 12,wherein the catalyst further comprises at least one of nickel andvanadium.
 14. The process according to claim 11, further comprisingproviding a regenerated catalyst proximate to an inlet of the reactionvessel and withdrawing a spent catalyst proximate to an outlet of thereaction vessel.
 15. The process according to claim 11, wherein thecatalytic cracking zone comprises a fluid catalytic cracking zone. 16.The process according to claim 15, wherein the hydrogen is at leastpartially comprised from a hydrocarbon product stream from the fluidcatalytic cracking zone.
 17. The process according to claim 16, furthercomprising fractionating and separating the hydrocarbon product streamto obtain a stream comprising hydrogen and ethene.
 18. An apparatus,comprising: A) a catalytic cracking zone for producing a hydrocarbonproduct stream; B) a fractionation zone receiving the hydrocarbonproduct stream and providing a light naphtha stream and a light cycleoil stream; C) a separation zone for separating a stream comprisinghydrogen and ethene from the light naphtha stream; D) a treatment zoneadapted to receive the stream comprising hydrogen and ethene, andcomprising a first removal zone for removing hydrogen sulfide, and awashing zone for removing ammonia; and E) a reaction vessel foralkylating and hydrogenating the light cycle oil stream; wherein thereaction vessel receives a feed comprising hydrogen and one or moreC2-C6 alkenes, and the light cycle oil stream wherein the light cycleoil and hydrogen are obtained from the hydrocarbon product stream. 19.The apparatus according to claim 18, wherein the catalytic cracking zonefurther comprises a regeneration zone that communicates with thereaction vessel for regenerating catalyst.
 20. The apparatus accordingto claim 18, wherein the catalytic cracking zone comprises a fluidcatalytic cracking zone.